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Zeng, Liqin (National Engineering Research Center for Inland Waterway Regulation, School of River and Ocean Engineering, Chongqing Jiaotong University) | Liu, Mingwei (National Engineering Research Center for Inland Waterway Regulation, School of River and Ocean Engineering, Chongqing Jiaotong University) | Ma, Yuanfei (National Engineering Research Center for Inland Waterway Regulation, School of River and Ocean Engineering, Chongqing Jiaotong University) | Zhu, Chenhao (National Engineering Research Center for Inland Waterway Regulation, School of River and Ocean Engineering, Chongqing Jiaotong University)
Due to the lack of specific specifications and standards, the anticorrosion process of steel structures in China's inland river wharf is mainly based on the practice of the harbor wharf. The continuous erosion of the anticorrosive coating of hydraulic steel structures, coatings fell off in a large range and caused the exposed and rusty steel structures, which directly affects the normal use of hydraulic steel structures. The erosion of anticorrosive coating on steel structures surface was a relatively long process, and the field test is not easy to track and observe at any time. In order to obtain the corresponding test results in a short time, and to predict the long-term corrosion behavior and service life of materials and structures, a set of accelerated erosion test device for anticorrosive coating was developed. It can be used to study the erosion law of anticorrosive coatings under different erosion conditions in the environment of sand flow.
With the development of water transport, steel structures are more and more used in inland river port structures, deep water wharf substructures and shipborne components. According to statistics, the world's waste steel materials due to corrosion account for more than 1/5 of the annual output, and the direct economic losses caused by steel corrosion in developed countries account for 2% ~ 4% of GDP (Grundmeier, 2000; Hagen, 2019; Mahdavi, 2019). After corrosion, steel structure will not only wear out the material, but also affect the stress of the structure, thus reducing the safety of the structure, which may cause huge loss of life and property.
Due to the lack of specific codes and standards, the anticorrosion process of steel structures in mountainous rivers and other inland rivers in China mainly refers to the practices of seaport wharf and the relevant codes for coating protection of steel structures for anticorrosion, viscoelastic materials are used to protect steel structures (Chen, 2015). According to the field investigation, the dry season alternates with the wet season, and the steel structure coating in the water level fluctuation area is scoured by the sand flow and the sun's irradiation, resulting in partial overall peeling off. Different parts of the steel structure are exposed to rust, and the corrosion is increasingly aggravated, as shown in Fig.1. The main reason for this phenomenon is the serious erosion of anti-corrosion coating on steel structure by sand flow in inland river environment (Liu, 2018).
Pragma is bringing the industry’s first 3D metal printed, ultrahigh expansion bridge plug to market, the Aberdeen-based company said in a press release. Its patented M-Bubble bridge plug has successfully completed final lab testing and is due to begin field trials by the end of 2020. Initially targeted at both the plug-and-abandonment (P&A) sector and water shutoff applications, the first M-Bubble addresses a gap in the market for a lower-cost, fast-turnaround, permanent plugging solution, with a high pressure differential (3,000 psi) capability, the company said. The plug can be set without additional cement to save rig time and “waiting-on-cement” time, which can accumulate significant savings for the operator, especially in deeper, extended-reach wells. It also provides barrier-integrity reassurance when there is the possibility of a poor cement bond or cement channeling occurring on the high side of deviated wells, the company added.
A state-of-the-art time-domain electromagnetic tool is presented that is capable of quantifying four barriers individually, and inspecting a fifth barrier qualitatively. The working physics and salient features of the tool and its underlying technology are described.
The new tool uses time-domain electromagnetic (TEM) or pulsed eddy current (PEC) technology, which has set the benchmark for individual quantitative tubular corrosion evaluation in multi-annular well systems (multiple concentric tubulars) in recent years. Time-domain electromagnetic tools widely used in the industry are currently capable of quantifying the individual metal thickness/loss in up to three barriers. The new tool employs three highly sensitive sensors to provide high-resolution analysis of the inner barrier, while providing sufficient radial depth of investigation for up to five barriers.
The above features and advantages of the new tool are supported by modeling and fixture test results. Additional modeling is shown to compare and contrast the resolution and radial depth of investigation of the three sensors. Case studies from actual wells are also presented that illustrate how three sensors enhance the performance of this technology. Corrosion evaluation of multi-barrier systems is a major component of well integrity management because it can provide timely and cost-effective information for planning well repairs if needed. The ability of the new tool to inspect more barriers is important because it gives the operator better information for more proactive well integrity management.
The novelty of the tool is in its ability to exploit the information-rich wideband pulsed excitation using three sensors that enhance the sensitivity to multiple barriers.
Well abandonment has traditionally not been thought of as a crucial part of a well’s life, though it is as much a part of a well’s life cycle as drilling and production. As such, traditional methods of abandoning a well utilizing cement and bridge plugs are still common practice among most operators throughout the world. Recently, however, operators have been challenged to find more cost-effective ways to abandon wells without jeopardizing the sealing integrity and have begun to look for "alternative" abandonment materials. Materials such as resins have been utilized by some as an alternative, but there have not been any major new developments in well abandonment materials for nearly 100 years. Although cement, bridge plugs and resins have their benefits, there are also limitations to their sealing capabilities. Bridge plugs lack a high expansion ratio required in some wells and rely on elastomers to seal, limiting their ability to seal in damaged tubing or open hole environments. Due to the unique properties of bismuth, plugs can be achieved with an expansion ratio of 3:1 and take the shape of the environment they are being set in. Cement is porous and lacks the ability to block gasses from migrating through it while bismuth has no porosity, making it an ideal material for stoping gas migration. Resins must be squeezed into an area and can take days to fully cure before a seal is created as opposed to bismuth which flows in a a well via gravity and solidifies to create a seal in a few hours. This paper will demonstrate a new way to create gas tight seals during well abandonment, overcoming the limitations of traditional methods and reducing the operator’s liability and potential environmental impact after decommissioning has been completed.
Determined efforts are being exerted to shore up the integrity of high-pressure high temperature (HPHT) gas wells, which includes studying all observed integrity failures and adjusting practices to prevent potential failures from reoccurring. In high-pressure high-temperature gas wells, casing thermal expansion is a challenge that should be considered in order to maintain the integrity of the well and surface equipment. The objective of the paper is to describe observed growth in a HP gas wells in relation to the wellhead temperature and how it behaves after cycling the well and how it can affect the annuli pressures.
As methodology, two elements varying during shutdowns were studied thoroughly to determine the extent of the impact they may have on the integrity of HP gas wells. These elements are pressure and temperature. While the linear increase of the wellhead growth with increasing temperature was apparent, the subsequent actions of shutting in the well to cool down and then reopening it led to further deterioration of the cement and the wellhead growth increased even further. The engineering solutions and stress analysis at surface facilities is designed to overcome the growth allowance.
The main observation looks at the temperature element and its effect on well integrity in that it analyses the temperature impact on the well’s tubulars and links it to the stresses caused to casing cement and the resulting wellhead growth. Study will also provide recommendations on maintaining well integrity and avoiding any further deterioration. The temperature impact was also observed in one of the wells after it was shut in and wellhead sensors were left to record shut-in wellhead pressure and temperature for about 14 hours. This gave a reasonable indication of how fast it takes for the wellhead to cool down to ambient conditions. In the subject well, the wellhead temperature dropped by 50% in about 2 hours.
As result of the study, in detail reasons for increased wellhead growth in HPHT gas wells and how to avoid it. It also gives recommendations on maintaining well integrity and reducing the impact of full contraction of the well’s tubulars during cooling; such as maintaining wells on constant production, minimizing open and shut-in cycling, and reducing the shut-in time duration.
Iskandar, Dedy (PHE – Operation & Production) | Hartawan, Iman B. (PHE – Operation & Production) | Soelistiyono, Dony (PHE – ONWJ) | Soetjipto, Hermanto (PHE – ONWJ) | Irfan, Fahmi (PT Trihasco Utama)
Pertamina Hulu Energi - Offshore North West Java, also known as PHE-ONWJ, owns 426 subsea pipelines from which only 185 are active operating to support PHE-ONWJ's production activity and the rest, 241 pipelines, are inactive which status is either remain idle or being preserved. Need to be noted that 67% or 284 pipelines aged more than 30 years, which is more than its design life. From which, 120 pipelines are still actively operating distributing fluids such as Oil, Gas and 3-phase. Multiple events of leak have occurred which implicates PHE-ONWJ's production activity.
Based on observation, more than 90% of leak events occurred, were caused by internal corrosion. The specific cause is that PHE-ONWJ pipelines transports such fluids that contains corrosive agents such high CO2 content, sands or solid particles, SRB and water.
The existing integrity management plan such as in-line inspection, fluid sampling, chemical injection and others have been performed onto several pipelines. However, since the size of PHE-ONWJ's pipeline network facility is complex and massive, to perform in-line inspection to all pipelines is not economically beneficial. Moreover, performing in-line inspection induced high risk and not all of the pipelines are piggable either because of its design or operating condition. Therefore, by considering such conditions mentioned previously, an effective and efficient pipeline integrity management developed based on corrosion rate prediction from topside piping within corrosion circuit with pipeline.
It is clear unwanted event such leak shall interrupt PHE-ONWJ production activity, moreover the age of most pipeline facility are old which means it has probability to fail, even though not all leak event associated with the age of the pipeline. To maintain and predict failure event such as leak or even rupture, a corrosion model has been developed. This model is constructed from combining several parameters which are; fluid sampling, In-Line Inspection of several pipelines with different services, Topside piping inspection data, Operating history and pipeline design data. The model generated in the form of an equation that associates topside piping corrosion rate and pipeline corrosion rate which both were obtained from inspection data and the boundary is operating and design history of the pipeline itself.
The developed model or equation is continuously validated as In-Line Inspection (ILI) performed onto several pipelines that previously has been assessed by using the internal corrosion model. Since the model developed, an accuracy ranging from 80-99% has been achieved in predicting maximum internal corrosion rate of PHE-ONWJ's pipeline. Which later on, this corrosion model become as a basis in determining pipeline's integrity status, remaining life and assisted in assessing the pipeline risk which outcome are mitigation / action plan. All of these were obtained by only using topside inspection data.
Even though the corrosion model developed is able to represent PHE-ONWJ's pipeline internal corrosion rate, further study should be done to be applicable onto other facility or even company pipelines. Therefore, a joint study may be made to create such corrosion model for pipelines. The goal is to have an in-depth approach in managing matured and unpigable pipeline integrity that operates across the world with such effectiveness and ensure all stakeholders that the pipeline is safe to operate.
Al-Ajmi, Abdullah (Kuwait Oil Company) | Al-Rushoud, Abdulaziz (Kuwait Oil Company) | Al-Naqa, Faisal (Kuwait Oil Company) | Chouhan, Manoj (Kuwait Oil Company) | Al-Mekhlef, Alanoud (Kuwait Oil Company) | Alasoosy, Fawaz (Baker Hughes) | Albohamad, Dalal (Baker Hughes) | Alshab, Mustafa (Baker Hughes) | Ismail, Maizura (Baker Hughes)
A successful cement job is a crucial element of obtaining and maintaining well integrity and ensuring safe and efficient hydrocarbon production. The success of cementation starts with a full understanding of good parameters such as formation characteristics and depends on a properly designed slurry and spacer system.
The most challenging part of cementing a wellbore is cementing one with a low fracture gradient. There's a high risk of formation breakdowns and hole instability if maximum allowable equivalent circulation densities (ECDs) are exceeded. In addition to severe losses and formation damage, the outcome includes inefficient placement of the cement that warrants time-consuming and costly operations to assure zonal isolation.
In Kuwait, first trial of a new generation of an environmentally friendly enhanced aqueous spacer system was used successfully in a highly deviated well for cementing the production casing covering shale formations. This paper discusses the design of the enhanced aqueous system and its technical features and benefits, which helped improve the cement bond and achieve zonal isolation.
The issue of global warming is widespread nowadays with an increase in the surface temperature of the earth. Carbon dioxide, CO2 emission from industrial energy is one of the contributing factors to this issue. The concept of CO2 storage is one of the potential solutions to achieve zero CO2 emissions from the oil and gas industry. In order to have an effective cost solution, existing wells are suggested as CO2 injection wells. Therefore, the structures of the existing wells are assessed to observe the sustainability of the well towards CO2 injection since the wells previously drilled without considering their potential secondary life.
Well screening is carried out through 19 development wells in the RSK field. The method used in this screening including; information gathering through the master database, selection of screening criteria and risk quantification. The screening criteria consist of cement quality and quantity, casing metallurgy and wellhead grade. The screening results will be categorized under three different risks; low, high and unknown-risk. Each of the categories and the evaluation methods will be discussed in-depth in this paper.
The assessment resulted in 44% of low-risk well, 50% of the high-risk well and the remaining 6% of the unknown-risk well. The high-risk well is when the well does not meet one or more screening criteria set out, while the low-risk well clearly shows the well fit all the standard as CO2 compliance well. The unknown-risk is classified when there is no sufficient information to do the evaluation. It can be observed that most of the high-risk wells are from the first drilling campaign, while the latest campaign contributes to most of the low-risk well. To reduce the severity of high-risk well, squeeze cementing, geopolymer cement, wellhead modification and workover can be suggested. At the same time, detailed report searching from operators and service companies can be recommended to unknown-risk well.
The study is a quick look well screening for CO2 storage well. In order to strengthen the screening result; reservoir continuity, caprock integrity and comprehensive well assessment concentrating on packer integrity, tubing integrity, injection pressure, internal and external pressure and corrosiveness of injection fluid can be carried out to transform the high-risk well into a low-risk well and classifying the unknown-risk into a specific class.
Sajjad, Farasdaq Muchibbus (PT Pertamina Hulu Energi) | Wirawan, Alvin (PT Pertamina Hulu Energi) | Chandra, Steven (Institut Teknologi Bandung) | Ompusunggu, Janico Zaferson Mulia (PT Pertamina Hulu Energi) | Prawesti, Annisa (PT Pertamina Hulu Energi) | Suganda, Wingky (PT Pertamina Hulu Energi) | Muksin, M. Gemareksha Jamaluddin (PT Pertamina Hulu Energi) | Amrizal, Amrizal (PT Pertamina Hulu Energi)
Tubular engineering design is essential for production operation, especially in the mature oil and gas fields. The complex interaction among oil, natural gas, and water, complemented with wax, scale, inorganic compound, and deformation brings complexity in analyzing tubular integrity. This challenging problem will be more severe if the wells are located in offshore environment, therefore finding the cause of tubing deterioration is a challenging.
Field X, which has been in production for 30 years, cannot avoid the possibility of tubular thinning and deformation. The degradation is slowly developed until severe alterations are observed on the tubing body. The current state of the wells is complicated since the deformation inhibits the fluid flow and increases the risk of wellbore collapse and complications during sidetracking, infill drilling, workover, and other production enhancement measures. The risks can be harmful in the long run if not mitigated properly.
The current condition encourages us to conduct more comprehensive study on tubular degradation. It is to model the multiple degradation mechanisms, such as corrosion, scaling, and subsidence, under the flowing formation fluid. The model is then coupled with reservoir simulation in order to provide a better outlook on tubular degradation. We used multiple case studies with actual field data to identify the dominant mechanism on tubular degradation. The case study cover various reservoir and fluid characteristics and also operations problems to develop general equation and matrix for risk analysis and field development considerations.
We present the degree of tubular degradation and its effect to overall field performance and economics. Current field practices do not encourage a thorough tubular assessment during early life of the wells, which create complex problem at later stage. The study indicates that a proper planning and preventive action should be performed gradually before tubular degradation becomes severe. The paper presents a field experience-based model and guideline matrix that is useful in developing new areas from the perspective of well and facilities integrity, so that the degradation-related issues could be recognized earlier.
The implementation of a well integrity management system in a mature liquid hydrocarbon storage field brought to light essential questions about the present condition and likely evolution of the barrier elements in the years to come. Are there defects in the cement sheaths that were not detected at the time of site construction more than 50 years ago? Are there aging processes, such as casing corrosion or cement degradation, that could limit the field's useful life or even present an immediate risk? And, finally, what were the exact properties of cement and casing, given that the information available in drilling reports is very limited?
At the start of the campaign, the perceived need and available technology meant using a logging tool requiring pressure, and therefore the inspection would typically involve 2 workovers and a period of 3 weeks. However, tool selection focused on the actual aging risks, together with the use of new transmitters and relentless operational optimization improved operational efficiencies allowing two wells to be logged in two consecutive days, with important savings in direct and indirect cost as well as minimization of operational risk. The cost reduction did not come at the expense of actionable information: the wireline tools selected, together with detailed preparation and carefully supervised execution led to outstanding data quality being collected.
The implementation of a consistent method of absolute log calibration and quantitative evaluation allowed us to characterize cement properties and defects, as well as their evolution with time. A salient signature, common to most storage sites in salt, is high cement quality across the salt, with a sudden unexpected, partial loss of bond across the anhydrite that overlies the rock salt formation. This was recognized as a benign form of "sulfate attack": The precipitation of secondary ettringite within the cement matrix results in expansion and thus debonding across the stiff anhydrite, whereas creeping salt pushes cement back on the casing. Lead cement densification was also observed near shallower aquifers, also rich in sulfates, with clamping provided by marls in this case. After optimizing the logging suite, it was concluded that there was no risk of erosion, wear or corrosion, external as well as internal. The analysis also improved understanding of cement behavior across salt and the role of creeping formations.
A streamlined approach at integrity assurance, whereby the right questions are asked by the management system, optimum inspection protocols are selected and carefully carried out, and acquired data is processed using advanced quantitative techniques, allowed us to understand characteristics and dynamics of barrier elements and to conclude that safe operation of the site is possible and that there is no fixed life span.